1. Field of the Disclosure
Embodiments disclosed herein relate generally to tubular connections. More specifically, embodiments of the present disclosure relate to a method and apparatus for controlling the rate of assembly of tubulars to maintain a rate within a selected set of parameters during make-up.
2. Background Art
Drilling wells in subsurface formations for oil and gas wells is expensive and time consuming. Formations containing oil and gas are typically located thousands of feet below the earth's surface. Therefore, thousands of feet of rock and other geological formations must be drilled through in order to establish production. Casing joints, liners, and other oilfield tubulars are frequently used to drill, complete, and produce wells. For example, casing joints may be placed in a wellbore to stabilize and protect a formation against high wellbore pressures (e.g., wellbore pressures that exceed a formation pressure) that could otherwise damage the formation. Casing joints are sections of pipe (e.g., steel or titanium), which may be coupled in an end-to-end manner by threaded connections, welded connections, or any other connection mechanisms known in the art.
It should be understood that certain terms are used herein as they would be conventionally understood, particularly where threaded tubular joints are connected in a vertical position along their central axes such as when making up a pipe string for lowering into a well bore. Typically, in a male-female threaded tubular connection, the male component of the connection is referred to as a “pin” member and the female component is called a “box” member. As used herein, “make-up” refers to engaging a pin member into a box member and threading the members together through torque and rotation.
Referring initially to FIG. 1, a rotary drilling system 10 including a land-based drilling rig 11 is shown. While drilling rig 11 is depicted in FIG. 1 as a land-based rig, it should be understood by one of ordinary skill in the art that embodiments of the present disclosure may apply to any drilling system including, but not limited to, offshore drilling rigs such as jack-up rigs, semi-submersible rigs, drill ships, and the like. Additionally, although drilling rig 11 is shown as a conventional rotary rig, wherein drillstring rotation is performed by a rotary table, it should be understood that embodiments of the present disclosure are applicable to other drilling technologies including, but not limited to, top drives, power swivels, downhole motors, coiled tubing units, and the like.
As shown, drilling rig 11 includes a mast 13 supported on a rig floor 15 and lifting gear comprising a crown block 17 and a traveling block 19. Crown block 17 may be mounted on mast 13 and coupled to traveling block 19 by a cable 21 driven by a draw works 23. Draw works 23 controls the upward and downward movement of traveling block 19 with respect to crown block 17, wherein traveling block 19 includes a hook 25 and a swivel 27 suspended therefrom. Swivel 27 may support a Kelly 29 which, in turn, supports drillstring 31 suspended in wellbore 33. Typically, drillstring 31 is constructed from a plurality of threadably interconnected sections of drill pipe 35 and includes a bottom hole assembly (“BHA”) 37 at its distal end.
As is well known to those skilled in the art, the weight of drillstring 31 may be greater than the optimum or desired weight on bit 41 for drilling. As such, part of the weight of drillstring 31 may be supported during drilling operations by lifting components of drilling rig 11. Therefore, drillstring 31 may be maintained in tension over most of its length above BHA 37. Furthermore, because drillstring 31 may exhibit buoyancy in drilling mud, the total weight on bit may be equal to the weight of drillstring 31 in the drilling mud minus the amount of weight suspended by hook 25 in addition to any weight offset that may exist from contact between drillstring 31 and wellbore 33. The portion of the weight of drillstring 31 supported by hook 25 is typically referred to as the “hook load” and may be measured by a transducer integrated into hook 25.
Generally, threaded tubular products (typically casing, but may apply to drill-pipe, drill-collars, etc, referred to as tubulars or joints) may be assembled, or made-up, on drilling rigs by holding a lower joint fixed in the rotary table and by turning and lowering an upper joint into the lower joint. The upper joint may be turned by using the topdrive and lowering may be accomplished using the drawworks. Alternatively, already made-up tubulars may be unthreaded, also known as break-out, to disassemble a tubular string.
While “spinning” the two joints together (while the threads are engaging), torque may be limited to a fraction of a desired connection torque until the threads have fully engaged. Once the threads have fully engaged, the rotating torque may rise to the spinning torque limit and the rotation may stall. To complete the connection process, the torque limit is then increased to a final desired connection value, at which point rotation may re-commence and stall again at the final desired torque value, or make-up torque, for the connection.
Once the threads on the upper and lower joints are engaged, a drilling operator must lower the tubular at a correct rate to successfully spin the joints together. If the joint is lowered too quickly or too slowly, the threading process may stall out prematurely, or damage the threads. To lower at the “correct” rate while the threads are spinning together, the drilling operator may watch the indicated hookload and may modulate the drawworks speed by hand. If the lowering speed is too great, then the hookload decreases and the drilling operator may slow down, and vice-versa. In addition, the drilling operator is responsible for watching the rig floor and the tubular joint to ensure the process is safely and properly conducted.
While lowering the first tubular to be stabbed into the second tubular, very accurate control of the lowering speed may be required. Typically, the drilling operator may use a joystick that is scaled to allow a maximum operating speed of the drawworks to be achieved at a full travel of the joystick. The drilling operator may enter a reduced maximum speed, which would achieve the fine control, but may then need to manually enter a faster speed in order to manipulate the assembled tubulars after threading is completed.
Accordingly, there exists a need for an improved control system which reduces drilling operator intervention during threading and unthreading of tubular connections.